Summary

Carbonate reservoirs comprise fractures, vugs, and cavities. Vugs have a large contribution to reserves of oil and gas, and the fractures provide effective paths for fluid flow in the reservoir. The triple-porosity (TP) model is an effective conceptual method for capturing rock matrix and vugs and the microfractures connecting them. However, these fractures and vugs are always nonhomogeneous. Macrofractures and vugs cannot be handled with a continuum scheme because of their low density and high conductivity.

In this approach, the TP conceptual model is implemented to characterize rock matrix, microvugs, and fractures. To capture the heterogeneity of fractures and vugs, macrofractures and vugs are represented explicitly with the discontinuum model. The boundaries of macrovugs and macrofractures are discretized into several elements. The boundary-element method (BEM) is used to handle flow into macrofractures and vugs. The finite-difference method is applied to handle flow within macrofractures. The flow within macrovugs is assumed to be pseudosteady state.

With a simple discretization of the boundaries of macrovugs and macrofractures, the proposed model is shown to efficiently simulate the behavior of fractured carbonate reservoirs with heterogeneity. The computational accuracy is demonstrated using an analytical model and numerical simulation. On the basis of the proposed model, the effect of the heterogeneity of macrofractures and vugs on pressure-transient behavior is analyzed. The results show that macrofractures and vugs cannot be handled with triple-continuum models analytically. There will be several “dips” on the derivative of the pressure curve if macrovugs are discretely handled. Also, discretely handling the fractures and vugs will make the calculated dimensionless pressure and the derivative pressure lower than those calculated with the triple-continuum models. After increasing the porosity of macrovugs, the pressure and the derivative will go down in the flow regimes dominated by macrovugs. The conductivity of macrofractures has a great impact on almost all the flow regimes except for boundary-dominated flow. Finally, a field case is used to show the application of the proposed semianalytical model.

The novelty of the new model is its ability to model the transient behavior of carbonate reservoirs with nonhomogeneous fractures and vugs. Furthermore, it provides an efficient method for characterizing the heterogeneity of multiscaled fractures and vugs.

In this paper, we couple Discrete Fracture Network (DFM) and multi-continuum model with Generalized Multiscale Finite Element Method (GMsFEM) for simulating flow in fractured and vuggy reservoir. Various scales of fractures are treated hierarchically. Fractures that have global effect are modeled by continua while the local ones are embedded as discrete fracture network based on the geologic observation. For independent vugs, a continuum is used to represent their effects with specific configuration that there's no intra-flow of this continua. GMsFEM enables us to systematically develop an approximation space that contains prominent sub-grid scale heterogeneous background information based on the multi-continuum and DFM model. Conforming unstructured mesh is used to surrender the application of random discrete fracture networks. This paper targets on the improvement of the flow simulation performance in complex high-contrast domain by extending the ability of multiscale method to modeling arbitrary discrete fracture network. This advancement by GMsFEM is motivated by the limited capability of Multiscale Finite Element Method (MsFEM) on modeling discrete fractures when multiple fracture networks present in same coarse block. Multiple numerical results are shown to validate the efficiency of our coupled method.

In this paper, geomechanics is coupled with reservoir flow for modeling the depletion and deformation in fractured vuggy carbonate reservoir. Different from the dual- and triple-porosity models or the coupled approaches in which the vugs are considered as a continuous porosity, the vugs are treated as virtual volumes in this study. For each vug, the fluid exchange at the vug-matrix interface is dynamically calculated with time evolution and the pore pressure in the vugs is updated through considering both the fluid material balance and the volume change due to the mechanical deformation of vug. The fluid-mechanical interaction in the rock matrix and natural fractures is calculated based on the framework of Biot's poroelstic theory. The mechanical and hydraulic interactions between vugs and matrix are preserved and the stress evolution due to the depletion can be dynamically updated. The results in this study show that, the depletion process is mainly controlled by the fluid storage of the vugs. Fluid modulus is thus a more sensitive parameter than the rock/fracture modulus in terms of the depletion. However, the rock/fracture modulus can also affect the deformation of the system and thus affect the volume and pressure changes of the vugs.

The modeling and numerical simulation of fluid flow in naturally fractured carbonate karst reservoirs are extremely challenging due to non-Darcy flow in vugs and caves connected by fracture networks. The momentum balance of such flow has been shown to be better described by the Brinkman equation both physically and mathematically, and many methods have been proposed in the literature dealing with the steady-state Brinkman model. We carry Brinkman's idea one step further and propose a transient flow model which consists of the Brinkman equation and a generalized material balance equation, and the latter has proven to be exact in the fractured carbonate karst reservoir. Finite differences are implemented for the solution of the proposed transient flow model. This solution method is more straightforward, easier to derive and implement, and more apt to generalization from 2D to 3D cases than alternative techniques.

Numerical simulation of the transient Brinkman model requires explicit solution of not only pressure at the center of each grid block, but also velocities at the interfaces between the blocks, which exaggerates the computational cost and makes the computational process more difficult and less stable. In this paper, we propose a simplified finite difference formulation of the transient Brinkman model, which significantly reduces the computational time of the simulation process, and improves accuracy and stability of the simulation results. We update our reservoir simulator with this new formulation and illustrate it with a complex 3D naturally fractured carbonate karst reservoir model. The results of this study form the foundation for future 3D multi-phase reservoir cases.

The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization.

The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations.

This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans.

The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations.

The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.

AbstractThe North Kuwait Jurassic Complex (NKJC) consists of six fields with four potential reservoirs in the Jurassic age naturally fractured carbonate formation. Current understanding of the complex, has led to 12 subdivisions of the area and potentially 48 separate compartments (segments) in the complex. These subdivisions are defined by fault boundaries supported by a combination of variations in fluid composition, initial pressures and free water levels estimated from capillary pressure and log saturation data.

Multi-scenario production forecasts based on integrated full field modeling were needed in the process of building a Field Development Plan (FDP) for the NKJC. An integrated Asset Modeling (IAM) framework is adopted where multiple separate reservoir models (up to 48 models) are coupled through global constraints in order to meet gas delivery targets. The solution uses a black oil delumping technique to obtain compositional wellstreams while running black oil simulation models. The adopted simulation framework provides us with all the benefits of a compositional full field simulation model while topping-up with two advantages i.e. computational speed and flexibility.

We discuss the impact of the IAM solution on the selection of the optimal development scenario given that these fields are in the early stages of production via an early production facility on line in 2008. Coupling of all fields/segments allows optimization over the entire production system rather than optimizing each field individually. This reduces the number of wells required to meet targets at any one time under any reservoir realization, while also staying within the surface network constraints.

BackgroundThe North Kuwait Jurassic Complex (NKJC) consists of six fields with four potential reservoirs (Najmah/Sargelu, Upper Marrat, Middle Marrat and Lower Marrat) in naturally fractured carbonate formations (Figure 1). The fields have been subdivided into 12 major areas based upon fault boundaries, supported by a combination of variations in fluid composition, initial pressures and free water level estimates. With the four producing formations, there are potentially 48 separate compartments (segments) in the complex. The reservoirs contain multiple fluid types at near critical conditions (Ghorayeb et al., 2008).

Compositions vary across the complex - fluid samples from some reservoirs exhibit a dew point pressure behavior (near-critical gas-condensate) while other reservoirs exhibit a bubble point pressure behavior (near-critical volatile oil). Consequently, some reservoirs in the NKJC need to be modeled as gas-condensate reservoirs and some others as volatile oil reservoirs.

Abstract

Technical studies, production and operations, and management of fractured carbonate gas reservoir with high H2S-content are difficult and uneconomical tasks to perform due to high toxicity and corrosivity of H2S. The optimization of conceptual design of these reservoirs may become cost efficient through the use of integrated simulation. However, to our knowledge, previous models do not well allow for the characteristics of complex flow through porous media in fractured carbonate gas reservoir with high H2S-content, nor do they consider the influence of the special physical and chemical changes on production performance, which makes the prediction of production behavior uncertain. In this paper, mechanisms of the gas-liquid-solid migration and formation damage resulting from sulfur deposition in fractured carbonate gas reservoir with high H2S-content were investigated by means of numerical simulation. A new gas-liquid-solid coupling model in fractured carbonate gas reservoir with high H2S-content, accounting for sulfur deposition, phase behavior variation, geochemical rock-water-gas interactions, adsorption, was presented. A modified equation of state was also used to describe phase behavior variation and combined with the integrated model. The model can forecast the production mechanisms and performance of fractured carbonate gas reservoir with high H2S-content, particularly, evaluate accurately and rapidly H2S concentration, mole content spatial distribution and dynamic change with pressure or time. This work can also promote safer development design to fractured carbonate gas reservoir with high H2S-content and avoid failure in operations.

Introduction

In South China, many carbonate gas reservoirs suffer of having large of hydrogen sulfide and other sulfur compounds. Technical studies, production and operations, and management of this type of carbonate gas reservoirs with high H2S-content are difficult and uneconomical tasks to perform due to high toxicity and corrosivity of H2S[1]Reduction in pressure and temperature also induced sulfur precipitation by a reduction in the solubility of the sulfur in the gas phase beyond its thermodynamic saturation point. These changes occur during production operations and can result in sulfur deposition in the reservoir, wellbore and surface facilities. Deposition of elemental sulfur in the near well bore area and within reservoir rocks may significantly reduce the inflow performance of gas wells. Thus, the optimization of conceptual design of these reservoirs may become cost efficient and difficult.

An early recognition of many problems due to sulfur deposition associated with the production of sour gas has been achieved. Kuo and Colsmann[2]developed the first mathematical model of a solid phase precipitation in porous medium and its influence on fluid flow. The model considered elemental sulfur as some of dissolved sulfur precipitates from the solution as a result of depletion of reservoir pressure. The results of the study showed a rapid buildup of solid sulfur around the well and significant deposition near the outer boundary of the reservoir. Hyne[3] presented a survey of more than 100 producing wells in Canada and Europe about field operations of sour gas production. The survey focused on sulfur deposition at the bottom of producing wells and showed that high bottom hole and wellhead temperatures and low wellhead pressures provide favorable conditions for sulfur deposition in well tubing. Al-Awadhy et al[4] performed the first study to investigate sulfur deposition in carbonate oil reservoirs. They conducted a single experiment and developed a numerical model describing the phenomena. Shedid and Zekri [5] conducted a detailed experimental study using a wide range of applied flow rates, different initial concentrations of sulfur and different rock permeability. The results of the study stressed the severity of the problem associated with sulfur deposition for different flow rates and under different initial sulfur concentrations of the crude oil. Shedid et al[6] carried out ten dynamic flow experiments using different crude oils of different sulfur and asphaltene concentrations and under different flow rates to investigate the simultaneous deposition of sulfur and asphaltene in porous media. The results of this study indicated the increase of simultaneous sulfur and asphaltene concentrations in the flowing oil increases and accelerates the permeability damage affects in carbonate reservoirs.